Squeeze Process For Reactivation Of Well Treatment Fluids Containing A Water-Insoluble Adsorbent

ABSTRACT

A process for fracturing a subterraneous formation in the production of an oil well is described. The process steps include injecting an initial charge of a mixture, the mixture being formed from at least a water-insoluble adsorbent and at least one well treatment agent, into a well bore formed in the subterraneous formation so as to form a downhole matrix within the formation; injecting a solution comprised of an additional amount of the well treatment agent into the formation after the initial charge of the at least one well treatment agent has been substantially depleted; and then pressurizing the well bore for a time and under conditions sufficient to reactivate the downhole matrix in the formation, so that the treatment agent activity of the matrix is increased relative to the treatment agent activity of the matrix just prior to injecting the solution.

REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part of U.S. application Ser. No.12/261,982, filed Oct. 30, 2008, now allowed, the disclosure of which isincorporated herein by reference.

TECHNICAL FIELD

This invention relates to methods for enhancing or facilitating oilfield production processes using water-insoluble adsorbents.

BACKGROUND

Water-insoluble adsorbents are used in the fracturing of hydrocarbonwells in geological formations as proppant components in, e.g., welltreatment fluids in which they provide a support matrix within theformation to keep the fracture open and facilitate the flow of wellproduction fluids. One type of water-insoluble adsorbent is activateddiatomaceous earth, which is also known as DE, TSS, diatomite, diahydro,kieselguhr, kieselgur or celite (hereinafter “DE”).

Gravel packs are often used to control particulate migration in suchproducing formations. A gravel pack typically consists of a mass ofparticulates which are packed around the exterior of a screening device.In order to be useful in gravel packing applications, such particulatesmust exhibit high strength and be capable of functioning in highpermeability formations.

Frac Packs are used in high permeability formations to stimulate highpermeability formations where a combination of fracturing treatment isperformed ending with packing of the fracture to the wellbore whicheliminates the need for screens.

Gravel Pack Screens can also be packed with proppant.

Frequently, the water-insoluble adsorbent-containing fluids injectedinto the well also include chemical additives (e.g., scale, corrosion,asphaltene or paraffin inhibitors) which impart useful chemicalproperties to the production fluids coming out of the formation.However, over time, the efficacy of the additives in admixture with thewater-insoluble adsorbent of the downhole fluid diminishes, or “playsout,” causing production issues when the chemical attributes imparted bythe well treatment additives are critical to efficient well production.

There exists, therefore, a significant and long-felt need for methods toincrease the longevity of the chemical performance of water-insolubleadsorbent-containing well treatment fluids.

SUMMARY OF THE INVENTION

This invention provides a unique and highly efficient method forrecharging deployed water-insoluble adsorbent-containing well treatmentfluids with one or more additional, active treatment agents. The methodsof this invention enable well fracture treatment to have a longereffective life, by enabling the existing matrix formed usingwater-insoluble adsorbents to be recharged with well treatment agentshaving beneficial chemical attributes for inhibition of various wellproduction issues created by, e.g., paraffin accumulation, corrosion orasphaltene buildup.

Thus, one embodiment of this invention is a process for fracturing asubterraneous formation in the production of an oil well, comprising

injecting an initial charge of a mixture, the mixture being formed fromat least a water-insoluble adsorbent and at least one well treatmentagent, into a well bore formed in the subterraneous formation so as toform a downhole matrix within the formation;

injecting a solution comprised of an additional amount of the welltreatment agent into the formation after the initial charge of the atleast one well treatment agent has been substantially depleted; and then

pressurizing the well bore for a time and under conditions sufficient toreactivate the downhole matrix in the formation, so that the treatmentagent activity of the matrix is increased relative to the treatmentagent activity of the matrix just prior to injecting the solution.

Another embodiment of this invention is a process which furthercomprises pressurizing the well bore to a pressure below the fracturingpressure, and preferably to a pressure in the range of about 500 toabout 15000 psia while remaining under the fracturing pressure of theformation.

Other embodiments of this invention are directed to gravel packing.

These and other features and embodiments of this invention will be stillfurther apparent from the ensuing description and appended claims.

FURTHER DETAILED DESCRIPTION OF THE INVENTION

The mixture charged to the well bore in the practice of this inventionis typically formed by bringing together a water-insoluble adsorbent andone or more of several possible well treatment agents. The welltreatment agents may include, for example, one or more paraffininhibitors, hydrate inhibitors, scale inhibitors, asphaltene inhibitors,or a mixture of any two or more of the foregoing. Suitable paraffininhibitors include, for example, paraffin crystal modifiers,dispersant/crystal modifier combinations, and the like. Particularparaffin crystal modifiers may include, for example, ethylene vinylacetate polymer (e.g., WAX CHECK 5384 available from BJ Services Companyof Houston, Tex.), fatty alcohol esters of olefin maleic anhydridecopolymers, acrylate polymers of fatty alcohol esters, and the like.Particular suitable dispersants may include, for example, dodecylbenzene sulfonate, oxyalkylated alkylphenols, oxyalkylated alkylphenolicresins and the like. Suitable hydrogen sulfide scavengers could include,for example, trihydroxyethyltriazine, and the like. Suitable hydrateinhibitors could include, for example, polyethoxy polyamine, and thelike. Suitable scale inhibitors include, for example, triethanolaminephosphate esters, and the like. Suitable asphaltene inhibitors include,for example, sorbitan monooleate, polyisobutylene succinic anhydride,and the like.

The water-insoluble adsorbents employed in mixtures of this inventioninclude activated carbon and/or coals, silica particulates, precipitatedsilica, silica (quartz sand), alumina, silica-alumina such as silicagel, mica, silicate, e.g., orthosilicates or metasilicates, calciumsilicate, sand (e.g., 20-40 mesh), bauxite, kaolin, talc, zirconia,boron and glass, including glass microspheres or beads, fly ash,zeolites, diatomaceous earth, finely divided minerals, fibers, groundalmond shells, ground walnut shells, ground coconut shells, fuller'searth and organic synthetic high molecular weight water-insolubleadsorbents, natural clays, preferably those natural clays having arelatively large negatively charged surface and a much smaller surfacethat is positively charged, and such clays as bentonite, illite,montmorillonite and synthetic clays. When the water-insoluble adsorbentis diatomaceous earth, the diatomaceous earth employed in mixtures ofthis invention is typically activated DE in the form of a substantiallydry, white powder prior to coming into contact with the other componentsof the mixture. Typically, the surface area of the water-insolubleadsorbent is about 1 m²/g to about 100 m²/g.

Preferred water-insoluble adsorbents include activated carbon, silicaparticulate, precipitated silica, zeolite, ground walnut shells,fuller's earth, and organic synthetic high molecular weightwater-insoluble adsorbents such as polystyrene-divinylbenzene beads, andthe like. Another preferred water-insoluble adsorbent is diatomaceousearth.

The proportion of water-insoluble adsorbent to treatment agent will ofcourse depend upon the agent(s) selected and the mixture performancedesired for given geological formation and drilling circumstances.Generally speaking, the weight ratio of water-insoluble adsorbent totreatment agent will be in the range of about 95:5 to about 70:30, butcan vary within or outside of this range for a given application andformation.

Other components of the mixture, besides the water-insoluble adsorbentand the treatment agent(s), may include, for example, the proppant(e.g., sand), cross linked borate esters, cross-linked polysaccharides,polymeric carbohydrates and the like, as well as mixtures thereof.

In the practice of this invention, the injection of an initial charge ofthe mixture into the well bore can be carried out in any conventionalmethod of injecting fluids into a well bore of an oil or gas well,whether for fracturing or for gravel packing. Such convention methodsinclude truck treating, continuous injection, or high pressure pumping,for example. The downhole matrix formed within the formation after theinitial charge of the mixture is comprised of the active ingredient on awater-insoluble adsorbent as part of the sand matrix.

For gravel packing in a sand control method, the mixture is placedadjacent to a subterranean formation to form a fluid-permeable matrixcapable of reducing or substantially preventing the passage of formationparticles from the subterranean formation into the well bore while atthe same time allowing passage of formation fluids from the subterraneanformation into the well bore.

When a screening device is employed, the screening device is placed in awell bore formed in a subterraneous formation before the injection ofthe mixture. The mixture is injected such that it is packed around theexterior of the screening device to provide a fluid-permeable matrixaround the screening device which is capable of reducing orsubstantially preventing the passage of formation particles from thesubterranean formation into the well bore while at the same timeallowing passage of formation fluids from the subterranean formationinto the well bore. In addition, the screen itself can be packed withthe water-insoluble adsorbent containing the well treatment agent.Various known screening devices may be used in accordance with theinvention, with particularly suitable examples being that described in,e.g., Harrison et al. in “Comparative Study of Prepacked Screens” SPE20027, April 1990, the disclosure of which is incorporated herein byreference, as well as the screen which is commercially available underthe SLIMFLO brand from BJ Services Company of Houston, Tex.

The step of injecting a solution comprised of an additional amount ofthe well treatment agent into the formation can be conducted anytimeafter the initial charge of mixture containing the well treatment agenthas been substantially depleted (i.e., has played out) so that thetreatment agent performance level has become unacceptable. The injectionmay be carried out in the same manner by which the initialwater-insoluble adsorbent-containing mixture was charged into the wellbore, and can be carried out in any conventional method of injectingfluids into a well bore of an oil or gas well, as mentioned above. Thesolution which is injected will typically be comprised of the desiredwell treatment agent(s) in a solution which further comprises a solvent.The relative amounts of the solvent and treatment agent of the solutionto be injected into the well bore will of course vary depending upon theagent and solvent involved, but will typically be of a solvent totreatment agent ratio in the range of about 10:90 to about 95:5, byweight. The solvent in one embodiment is xylene, toluene, or a heavyaromatic distillate and possible mixtures of all three. When a mixtureof all three is considered for such embodiment, the relative amounts ofeach solvent component can vary, but will be typically in variableweight ratios (xylene:toluene:heavy aromatic distillate) such as10:70:20, 20:70:10, 70:20:10 or 20:10:70. In another embodiment, thesolvent can be water (for water soluble well treatment agents).

After the injection step is carried out, the well bore is pressurizedfor a time and under conditions sufficient to reactivate the downholematrix in the formation. This pressurization of material in the wellbore and formation fracture is commonly referred to as a “squeeze.”Reactivation of the treatment agents downhole has occurred through thesqueeze process as long as the treatment agent activity of the in-placematrix is increased relative to the treatment agent activity of thematrix just prior to injecting the solution. The determination ofwhether the treatment agent activity has increased relative to theactivity of that agent just prior to injection of the solution andcompletion of the squeeze is made through conventional residual analysisand comparison of the same before and after the squeeze, andconventional analysis of the physical well parameters, e.g., theproduction rate of the well and well pressure.

The pressure to which the well bore is pressurized in the squeezeprocess typically will be a pressure below the fracturing pressure, andwhen applicable, below the pressure that would cause the gravel pack tobreak up. In one embodiment of the invention, the pressure is in a rangeof about 500 to about 15000 psia. The duration for which the pressurecondition is applied to the well will vary, depending upon the ease offracturing, but will typically be in the range of about 2 to about 10hours.

The following examples are presented for purposes of illustration, andare not intended to impose limitations on the scope of this invention.

A suitable process for conducting an experimental squeeze will now bedescribed. Place into a column of Ottawa sand (no. 20/40 grit size) anamount of activated DE (untreated) in the range of about 1 to about 2 wt%, based upon the total sand weight. To this column a brine solution isadded to simulate well conditions. The column with brine solution isthen charged with a white oil (with no additives) under pressure in therange of about 2000 to 3000 psi, fed from an oil reservoir. Thisprovided the baseline standard run without any active well treatmentagent added to the DE.

EXAMPLE 1

PARASORB 5000 (paraffin inhibitor) Fracture Life @ 2% Loading in Ottawa20/40 Sand

Packed column studies were conducted on a paraffin inhibitor (PARASORB5000 proppant commercially available from BJ Services Company andpreviously branded or referred to as PARASORB 1), using UNION 76 whiteoil. The column was packed with 2% PARASORB 5000 proppant and 98% Ottawa20/40 sand. Elution of a Miocene brine prior to white oil elution wasconducted to water wet the matrix and elution of the white oil followed.A pressure capable column was fitted with heat tape and a temperaturecontroller, and the white oil was pumped at 2,000 to 2,500 psi. Thevolume of effluent was measured, and periodic samples were taken todetermine if the PARAS ORB 5000 product was still effective as a pourpoint depressant. Oil, known to react favorably to the active pourdepressant in the PARASORB 5000, was used to measure pour pointdepressant effectiveness of each of the effluent fractions. The firstpart of the test consisted of squeezing (e.g., the active pourdepressant at 5% active in Kerosene was introduced from the well side ofthe tubing onto the column) on a conditioned sand column, and passingseveral thousand pore volumes of oil through it. Periodic samples weretaken during the elution period.

The second part of the test consisted of re-packing the column with 2%diatomaceous earth (e.g., the solid support for the active pour pointdepressant in PARASORB 5000) and squeezing the active ingredient ontothe column as a liquid, and measuring the before and after concentrationof the paraffin inhibitor by pour point reduction analysis against astandard curve on a treated oil sample at the different concentrations.After this, the white oil is again pumped through the column andperiodic samples are tested for pour point reduction.

The results of this testing showed that the native Ottawa sand retainedthe pour point depressant for the first few pour volumes but dropped offto nearly nothing after the first sample (e.g., no pour pointdepression) was obtained. In stark contrast, the second part of the test(e.g., where the diatomaceous earth was present on the column) gaveactive levels of pour point depressant for over 10,000 pore volumes.This means that under moderate production conditions (say 50 Bbl/day)this reactivated fracture job could last nearly 7 years.

The PARASORB 5000 gave a surprisingly long period of effectiveness foran organic paraffin treatment, and gave no appearance of declining afterseveral thousand pore-volumes of white oil exposure.

EXAMPLE 2

SALTSORB 7020 Fracture Life @ 2% Loading in Ottawa 20/40 Sand

Packed column studies were conducted on a proppant containing sodiumchloride inhibitor (sold under the brand name SALTROL 7017 andcommercially available from BJ Services Company; the formed proppantbeing commercially available from BJ Services Company under the brandname SALSORB 7020) using saturated salt-water brine. The column waspacked with 2% SALTSORB 7020 proppant and 98% Ottawa 20/40 sand. Apressure capable column was fitted with heat tape and a temperaturecontroller, and the saturated sodium chloride brine was pumped at 2,000to 2,500 psi and 185° F. The volume of effluent was measured, andperiodic samples were taken to determine if the SALTSORB 7020 productwas still effective as sodium chloride scale inhibitor. Samples were setaside and observed for the formation of salt crystals after variousnumbers of pore volumes had passed through the column. The first part ofthe test consisted of squeezing (e.g., the active component, SALTROL7017 was introduced from the well side of the tubing onto the column) ona conditioned sand column, and passing several thousand pore-volumes ofsaturated salt water through it. The second part of the test consistedof re-packing the column with 2% diatomaceous earth (e.g., the solidsupport for the active pour point depressant in SALTSORB 7020) andsqueezing the active ingredient onto the column. After this thesaturated sodium chloride brine is again pumped through the column andperiodic samples are tested for salt crystal inhibition. The results ofthis testing showed that the native Ottawa sand retained the saltcrystal inhibitor for the first few pour volumes but dropped off tonearly nothing after the first eluent fraction was obtained. The samewas true of the sample squeezed on diatomaceous earth in the fracturingsand. This was due to the fact that there was no difference in thenon-absorbed SALTROL 7017 versus the SALTROL absorbed on effluentsamples (e.g., each gave salt crystals on standing).

The SALTSORB 7020 gave a surprisingly short period of effectiveness fora sodium chloride treatment. This is probably because the SALTROL 7017is extremely soluble in the brine water at elevated temperatures (e.g.,185° F.), and is completely removed after only a few pore volumes ofbrine eluent passes.

EXAMPLE 3

SCALESORB 3 Fracture Life @ 2% Loading in Ottawa 20/40 Sand

Packed column studies were conducted on a proppant containing scaleinhibitor (sold under the brand SCALTROL and commercially available fromBJ Services Company, Houston, Texas, the formed proppant beingcommercial available from the same company under the brand SCALESORB 3)using clean de-ionized water. The column was packed with 2% SCALESORB 3proppant and 98% Ottawa 20/40 sand. A pressure capable column was fittedwith heat tape and a temperature controller, and the de-ionized waterwas pumped at 2,000 to 2,500 psi and 185° F. The volume of effluent wasmeasured, and periodic samples were taken to determine if the SCALTROLproduct was still effective as scale inhibitor by conductingspectroscopic measurements of phosphate. Samples were submitted toanalytical testing for the presence of phosphates after various numbersof pore volumes had passed through the column. The first part of thetest consisted of squeezing (e.g., the active component of SCALESORB 3was introduced from the well side of the tubing onto the column) on aconditioned sand column, and passing several thousand pore-volumes ofde-ionized water through it. The second part of the test consisted ofre-packing the column with 2% diatomaceous earth (e.g., the solidsupport for the active scale inhibitor SCALESORB 3) and squeezing theactive ingredient onto the column. After this the de-ionized water isagain pumped through the column and periodic samples are tested forphosphorous. The results of this testing showed that the native Ottawasand retained the scale inhibitor for the first few pour volumes butdropped off to nearly nothing after the first eluent fraction wasobtained. The same was true of the sample squeezed on diatomaceous earthin the fracturing sand. This was due to the fact that there was nodifference in the non-absorbed scale inhibitor versus the scaleinhibitor absorbed on effluent samples.

The non adsorbed scale inhibitor gave a surprisingly short period ofeffectiveness as the phosphorous content showed. Without being bound totheory, it is believed that, because the scale inhibitor is extremelysoluble in the de-ionized water at elevated temperatures (e.g., 185°F.), it is completely removed after only a few pore volumes ofde-ionized eluent passes.

Additional embodiments of the invention are as follows:

A) A process which comprises:

-   -   injecting an initial charge of a mixture, the mixture being        formed from at least a water-insoluble adsorbent and at least        one well treatment agent, into a well bore formed in a        subterraneous formation;    -   placing the mixture adjacent to the subterranean formation to        form a fluid-permeable matrix that is capable of reducing or        substantially preventing the passage of formation particles from        the subterranean formation into the well bore while at the same        time allowing passage of formation fluids from the subterranean        formation into the well bore; and then    -   pressurizing the well bore for a time and under conditions        sufficient to reactivate the matrix in the formation, so that        the treatment agent activity of the matrix is increased relative        to the treatment agent activity of the matrix just prior to        injecting the solution, wherein the water-insoluble adsorbent is        diatomaceous earth, activated carbon, silica particulate,        precipitated silica, zeolite, ground walnut shells, fuller's        earth, or an organic synthetic high molecular weight        water-insoluble adsorbent, wherein the process has at least one        of the following features:        -   (i) the well treatment agent is selected from the group            consisting of a paraffin inhibitor, a salt inhibitor, a            scale inhibitor, an asphaltene inhibitor and a mixture of            two or more of the foregoing;        -   (ii) the well bore is pressurized to a pressure below the            pressure which causes the matrix to break up.

B) The process of A), wherein the well treatment agent is a paraffininhibitor comprised of a paraffin crystal modifier, which paraffincrystal modifier is comprised of an ethylene vinyl acetate polymer.

C) The process of A), wherein the pressure is in a range of about 250 toabout 15000 psia.

D) The process of C), wherein the pressure is in a range of about 500 toabout 15000 psia.

E) A process which comprises:

-   -   placing a screening device in a well bore formed in a        subterraneous formation;        -   injecting an initial charge of a mixture, the mixture being            formed from at least a water-insoluble adsorbent and at            least one well treatment agent, into the well bore, wherein            the mixture is injected into the well bore such that the            mixture is packed around the exterior of the screening            device to provide a fluid-permeable matrix around the            screening device which is capable of reducing or            substantially preventing the passage of formation particles            from the subterranean formation into the well bore while at            the same time allowing passage of formation fluids from the            subterranean formation into the well bore; and then        -   pressurizing the well bore for a time and under conditions            sufficient to reactivate the matrix in the formation, so            that the treatment agent activity of the matrix is increased            relative to the treatment agent activity of the matrix just            prior to injecting the solution, wherein the process has at            least one of the following features:            -   (i) the well treatment agent is selected from the group                consisting of a paraffin inhibitor, a salt inhibitor, a                scale inhibitor, an asphaltene inhibitor and a mixture                of two or more of the foregoing;            -   (ii) the well bore is pressurized to a pressure below                the pressure which causes the matrix to break up.

F) The process of E), wherein the process has features (i) and (ii),wherein the well treatment agent is a paraffin inhibitor comprised of aparaffin crystal modifier, which paraffin crystal modifier is comprisedof an ethylene vinyl acetate polymer, and wherein the pressure is in arange of about 500 to about 15000 psia.

G) The process of E), wherein the well treatment agent is a paraffininhibitor comprised of a paraffin crystal modifier, which paraffincrystal modifier is comprised of an ethylene vinyl acetate polymer.

H) The process of E), wherein the pressure is in a range of about 250 toabout 15000 psia.

I) The process of H), wherein the pressure is in a range of about 500 toabout 15000 psia.

J) A process as in any of E) to I) wherein the water-insoluble adsorbentis diatomaceous earth, activated carbon, silica particulate,precipitated silica, zeolite, ground walnut shells, fuller's earth, oran organic synthetic high molecular weight water-insoluble adsorbent

K) A process as in J) wherein the water-insoluble adsorbent isdiatomaceous earth.

It is to be understood that the reactants and components referred to bychemical name or formula anywhere in this document, whether referred toin the singular or plural, are identified as they exist prior to cominginto contact with another substance referred to by chemical name orchemical type (e.g., another reactant, a solvent, or etc.). It mattersnot what preliminary chemical changes, transformations and/or reactions,if any, take place in the resulting mixture or solution or reactionmedium as such changes, transformations and/or reactions are the naturalresult of bringing the specified reactants and/or components togetherunder the conditions called for pursuant to this disclosure. Thus thereactants and components are identified as ingredients to be broughttogether in connection with performing a desired chemical operation orreaction or in forming a mixture to be used in conducting a desiredoperation or reaction. Also, even though an embodiment may refer tosubstances, components and/or ingredients in the present tense (“iscomprised of”, “comprises”, “is”, etc.), the reference is to thesubstance, component or ingredient as it existed at the time just beforeit was first contacted, blended or mixed with one or more othersubstances, components and/or ingredients in accordance with the presentdisclosure.

Also, even though the claims may refer to substances in the presenttense (e.g., “comprises”, “is”, etc.), the reference is to the substanceas it exists at the time just before it is first contacted, blended ormixed with one or more other substances in accordance with the presentdisclosure.

Except as may be expressly otherwise indicated, the article “a” or “an”if and as used herein is not intended to limit, and should not beconstrued as limiting, the description or a claim to a single element towhich the article refers. Rather, the article “a” or “an” if and as usedherein is intended to cover one or more such elements, unless the textexpressly indicates otherwise.

Each and every patent or other publication or published documentreferred to in any portion of this specification is incorporated in totointo this disclosure by reference, as if fully set forth herein.

This invention is susceptible to considerable variation in its practice.Therefore, the foregoing description is not intended to limit, andshould not be construed as limiting, the invention to the particularexemplifications presented hereinabove.

1. A process comprising injecting an initial charge of a mixture, themixture being formed from at least a water-insoluble adsorbent and atleast one well treatment agent, into a well bore formed in asubterraneous formation so as to form a downhole matrix within theformation; injecting a solution comprised of an additional amount of thewell treatment agent into the formation after the initial charge of theat least one well treatment agent has been substantially depleted; andthen pressurizing the well bore for a time and under conditionssufficient to reactivate the down-hole matrix in the formation, so thatthe treatment agent activity of the matrix is increased relative to thetreatment agent activity of the matrix just prior to injecting thesolution.
 2. A process as in claim 1 wherein the water-insolubleadsorbent is activated carbon, silica particulate, precipitated silica,zeolite, ground walnut shells, fuller's earth, or an organic synthetichigh molecular weight water-insoluble adsorbent.
 3. The process of claim2, wherein the process has at least one of the following features: (i)the well treatment agent is selected from the group consisting of aparaffin inhibitor, a salt inhibitor, a scale inhibitor, an asphalteneinhibitor and a mixture of two or more of the foregoing; (ii) the wellbore is pressurized to a pressure below the fracturing pressure.
 4. Theprocess of claim 3, wherein the well treatment agent is a paraffininhibitor comprised of a paraffin crystal modifier.
 5. The process ofclaim 4, wherein the paraffin crystal modifier is comprised of anethylene vinyl acetate polymer.
 6. The process of claim 3, wherein thepressure is in a range of about 250 to about 15000 psia.
 7. The processof claim 6, wherein the pressure is in a range of about 500 to about15000 psia.
 8. The process of claim 3, wherein the process has features(i) and (ii), wherein the well treatment agent is a paraffin inhibitorcomprised of a paraffin crystal modifier, and wherein the pressure is ina range of about 250 to about 15000 psia.
 9. The process of claim 8,wherein the paraffin crystal modifier is comprised of an ethylene vinylacetate polymer.
 10. A process which comprises: injecting an initialcharge of a mixture, the mixture being formed from at least awater-insoluble adsorbent and at least one well treatment agent, into awell bore formed in a subterraneous formation; placing the mixtureadjacent to the subterranean formation to form a fluid-permeable matrixthat is capable of reducing or substantially preventing the passage offormation particles from the subterranean formation into the well borewhile at the same time allowing passage of formation fluids from thesubterranean formation into the well bore; and then pressurizing thewell bore for a time and under conditions sufficient to reactivate thematrix in the formation, so that the treatment agent activity of thematrix is increased relative to the treatment agent activity of thematrix just prior to injecting the solution.
 11. A process as in claim10 wherein the water-insoluble adsorbent is diatomaceous earth,activated carbon, silica particulate, precipitated silica, zeolite,ground walnut shells, fuller's earth, or an organic synthetic highmolecular weight water-insoluble adsorbent.
 12. The process of claim 10,wherein the process has at least one of the following features: (i) thewell treatment agent is selected from the group consisting of a paraffininhibitor, a salt inhibitor, a scale inhibitor, an asphaltene inhibitorand a mixture of two or more of the foregoing; (ii) the well bore ispressurized to a pressure below the pressure which causes the matrix tobreak up.
 13. The process of claim 12, wherein the well treatment agentis a paraffin inhibitor comprised of a paraffin crystal modifier. 14.The process of claim 12, wherein the process has features (i) and (ii),wherein the well treatment agent is a paraffin inhibitor comprised of aparaffin crystal modifier, and wherein the pressure is in a range ofabout 250 to about 15000 psia.
 15. The process of claim 14, wherein theparaffin crystal modifier is comprised of an ethylene vinyl acetatepolymer.
 16. A process which comprises: placing a screening device in awell bore formed in a subterraneous formation; injecting an initialcharge of a mixture, the mixture being formed from at least awater-insoluble adsorbent and at least one well treatment agent, intothe well bore, wherein the mixture is injected into the well bore suchthat the mixture is packed around the exterior of the screening deviceto provide a fluid-permeable matrix around the screening device which iscapable of reducing or substantially preventing the passage of formationparticles from the subterranean formation into the well bore while atthe same time allowing passage of formation fluids from the subterraneanformation into the well bore; and then pressurizing the well bore for atime and under conditions sufficient to reactivate the matrix in theformation, so that the treatment agent activity of the matrix isincreased relative to the treatment agent activity of the matrix justprior to injecting the solution.
 17. A process as in claim 16 whereinthe water-insoluble adsorbent is diatomaceous earth, activated carbon,silica particulate, precipitated silica, zeolite, ground walnut shells,fuller's earth, or an organic synthetic high molecular weightwater-insoluble adsorbent.
 18. The process of claim 16, wherein theprocess has at least one of the following features: (i) the welltreatment agent is selected from the group consisting of a paraffininhibitor, a salt inhibitor, a scale inhibitor, an asphaltene inhibitorand a mixture of two or more of the foregoing; (ii) the well bore ispressurized to a pressure below the pressure which causes the matrix tobreak up.
 19. The process of claim 18, wherein the well treatment agentis a paraffin inhibitor comprised of a paraffin crystal modifier. 20.The process of claim 18, wherein the process has features (i) and (ii),wherein the well treatment agent is a paraffin inhibitor comprised of aparaffin crystal modifier, and wherein the pressure is in a range ofabout 250 to about 15000 psia.